The modern history of the production of fluid hydrocarbons begins in the latter half of the 19th century with the vision of a few promoters seeking to exploit “rock oil”. Rock oil, as opposed to animal fats or vegetable oil, was observed seeping into salt wells in the isolated wooded hills of western Pennsylvania. From that modest birth, by the 20th century, petroleum production had become a predominate world industry. As that industry has developed, the underlying technology has advanced concomitantly.
While wells within some geologic regions are capable of producing under naturally induced reservoir pressures, more commonly encountered are well facilities which employ some form of artificial lift-based production procedure. The purpose of artificial lift is to maintain a reduced producing bottom hole pressure (BHP) such that the involved geologic formation can give up desired reservoir fluids. If a predetermined drawdown pressure can be maintained, a well will produce desired fluids notwithstanding the form of lift involved. In general, lift systems may involve sucker rod pumping (beam pumping), gas lift, electrical submersible pumping, hydraulic pumping, jet pumping, plunger lift, as well as other modalities. See generally:                Brown et al., “The Technology of Artificial Lift Methods, Vol. 2a, Pennwell Publishing Co., Tulsa, Okla. (1980).        
One widely employed approach to hydrocarbon fluid production is a non-pumping gas lifting one wherein a cyclical opening and closing of a well is carried out. Generally referred to as “intermitting”, this cyclical process provides alternating on-cycles and off-cycles which are established by the operation of a gas driven motor valve which, when utilized in conjunction with gas production, functions to produce gas to a sales line and is referred to as a “sales valve”.
The timing involved in intermitting a well has long been considered critical, the timing of on-cycles and off-cycles having been a taxing endeavor to well production. In this regard, early endeavors called upon the technician to monitor many well parameters including tubing pressure, casing pressure, sales line pressure and many other heuristic details. A failure of the intermitting process would typically result in an excessive quantity of liquids being accumulated within the tubing string of the well, a condition generally referred to as “loading up” of the well. This condition represents a failure which may be quite expensive to correct.
For a substantial period of time, control over the cyclical production of wells was based simply upon a crude, clock-operated device. This device required hand winding and thus well location visitation by technicians on a quite frequent basis. Inasmuch as those locations are, for the most part, difficult to access the earlier spring-wound controllers were a source of much frustration to industry. That frustration commenced to end with the introduction to the industry of a long life battery operated controller by W. L. Norwood about 1978. Described in U.S. Pat. No. 4,150,721, entitled Gas Well Controller System, issued Apr. 24, 1979, this seminal and pioneer electric controller provided for long term, battery operated control over wells and served to simplify the control adjustment procedure required of well technicians. Of particular importance, the controller was designed to respond to system parameters to override the cycle timing to accommodate conditions wherein such timing should be overridden and subsequently reinitiated on an automatic basis. Sold under the trademark “Digitrol”, the controller, incorporated in a classic green metal box, is still seen to be performing on wells and has had a profound impact upon well production.
At about the time of the introduction of the Norwood controller, some leading petroleum engineers were promoting a plunger method of artificial lift wherein an untethered piston which is referred to as a “plunger” is slidably installed within the tubing string of the well and is permitted to travel the entire length of that tubing string in conjunction with the on-cycles and off-cycles of the well. While promising many advantageous aspects of well production, the plunger lift approach to artificial lift was hindered by a lack of appropriate control. The Norwood controller, being able to respond to plunger arrival at a wellhead essentially permitted the creation of a successful plunger lift based industry.
In 1980, W. L. Norwood introduced the first practical microprocessor driven controller to the industry. This instrument, marketed under the trademark “Liquilift”, gave well technicians a substantially expanded capability and flexibility for well control, providing for response to a substantial number of well parameters, as well as for the development of delay techniques to accommodate for temporary system excursions and the like. The initial version of the Liquilift device is described in U.S. Pat. No. 4,352,376 by Norwood, entitled “Controller for Well Installations”, issued Oct. 5, 1982.
In 1991, Rogers, Jr., introduced a control technique for plunger lift wells which optimized production through the evaluation of the speed at which the plunger arrives at the wellhead. Deviations from this optimum speed are detected and afterflow times as well as off cycle intervals were then varied to, in effect, “tune” the well toward optimum plunger speed performance. Where excessive low plunger speed was encountered, a second motor valve referred to as a tank or vent valve was opened to vent the well, in effect, to atmospheric pressure. The production technique had a profound impact upon the industry, improving gas production performance, for example, from about 50% to as high as 150%.
The gas lift approach to artificial lift is a method of lifting fluid wherein relatively high pressure gas is used as the lifting medium in a mechanical form of process. In general, gas lift methodology may involve a continuous flow approach or may employ an intermittent lift technique. In continuous flow, a continuous volume of high-pressure gas is introduced to the well to aerate or lighten the fluid column until reduction of the bottom hole pressure will allow sufficient differential across the sand face. To accomplish this, a flow valve is used that will permit the deepest possible one point injection of available gas lift pressure in conjunction with a valve that will act as a changing or variable orifice to regulate gas injected at the surface. This approach is used in wells with a high productivity index (PI) and a reasonably high bottom hole pressure (BHP) relative to well depth.
An intermittent flow gas lift approach involves expansion of a high pressure gas ascending to a low pressure outlet. This high pressure gas is called upon to drive a slug of liquid from the well. Typically, the intermittent lift is accomplished through the utilization of a multi-point injection of gas through more than one gas lift valve. For such an approach, the installation is designed so that the lowest gas lift valve is opened just as the bottom of the liquid slug passes each such valve. Gas lift approaches, however are inefficient in that there is about a 7% fallback of liquids from the, slug for each 1,000 feet of well depth. In this regard, for example, for a well of 10,000 feet depth, 70% of the slug of liquid may be left in the well for each intermitting cycle. Accordingly, much of the energy employed in injecting compressed gas into the well is wasted. Gas lift installations also are hindered by a somewhat ineffective removal of solids such as sand or scale which may accumulate in the well. By contrast, plunger lift procedures will drive such materials from the well by virtue of the necessarily involved efficient plunger to liquid interface. Intermitting approaches to artificial lift procedures also may adversely effect the geologic zone of production involved. In this regard, the well is closed in for an off-cycle interval during which pressure builds against that zone. The effect is more pronounced where injected lifting gas is pressurized against that zone.
Intermitting gas lift installations also will pose problems at the gathering system associated with a well. Such gathering systems are composed of all the lines, separators and low-pressure volume chamber that supply gas to the suction side of the gas lift compressor. If the gas lift cycles are far apart in time, the compressor will be starved of gas between cycles and excessive make-up gas will be required. One solution described for this problem suggests the use of low-pressure volume chamber which save gas for the compressor. Where continuous flow wells are present the problem is substantially ameliorated.
Some gas producing wells are characterized in exhibiting a very high production index (PI). As a consequence, the length of casing perforation admitting production zone gas, referred to as the perforation or pay interval, can be quite extensive, for example, up to about 1,500 feet. Producing these wells with plunger lift procedures is problematic since the tubing string cannot extend to the well bottom which will be located below the perforation zone and determining an end position for inflow with respect to the perforation interval is difficult. The reservoir characteristic associated with these wells also may evoke a low bottom hole pressure (BHP) condition such that significant accumulation of liquids are encountered. A resultant liquid pressure head militates against effective gas production and thus, its removal is called for.
A technique of injection gas lift referred to as a “chamber installation” often is elected for these low BHP, high PI characterized wells.                Often a chamber installation increases the total oil production. A chamber is an ideal installation to run in a low BHP, high PI well. This well will produce fairly high fluid volumes if a high drawdown is created on the sand face. A chamber allows the lowest flowing BHP possible to obtain by gas lift. The chamber uses the casing volume to store fluids. Brown et al., (supra), pp 125–126.These chambers may assume a variety of configurations, but function to use the casing volume to store fluids and lower the liquid pressure head. However, as noted above, gas injection lift procedures for these typically deep wells are inefficient due to significant fallback or slippage of the liquid being driven from the well. Where chamber lift is employed fallback falls to 5% per 1000 feet, only a slight improvement, however inefficiency remains significant. See Brown et al., (supra) p 324.        
In the same well installations, the liquids are removed with down hole rod string driven pumps. However, in the gassy environment of the wells such positive displacement devices tend to ingest gas and commence to become what is referred to as being “gas locked”. As a consequence, the pumps become quite inefficient and are subject to failure. Rod string pump actuation, in and of itself, is difficult in deep wells due to material strain. Further, the pumps must be shut-in periodically to permit liquid buildup such that they can be loaded with liquid to commence pumping. Of course, the pumps are not immune from damage due to solid accumulations at the down hole location.